Hydrocarbon production in a subsea environment is a capital intensive, time-consuming and challenging process. The cost of nearby deepwater offshore structures or hosts to support exploration and production has become increasingly prohibitive, particularly in deep water (in excess of 3000 feet). Producers have been forced to investigate the economic and technical feasibility of subsea production systems that are tied back to existing offshore structures that may be many miles away. While the production stream may leave the wellhead at an elevated temperature, it is rapidly chilled as it travels many miles in a deepwater environment, where temperatures may be on the order of 5° C.
A subsea production stream may be comprised of water or brine, gas, oil, together with dissolved solids such as waxes, asphaltenes, organic and inorganic salts. At high temperatures and pressures, the dissolved solids remain in solution. However, once the production stream leaves the wellhead, it begins to cool and the pressure is reduced when compared to wellhead pressure. These changes in temperature and pressure result in the dissolved solids precipitating and the creation of new solids. Inorganic salts may precipitate as scale on the pipeline; the dissolved asphaltenes and waxes will form solids that may adhere to the internal walls of the pipeline. Moreover, the gas and water may react to form solid hydrates that may likewise adhere to the walls of the pipeline. As the solids precipitate and solid hydrates form, they can, over time reduce the throughput of the pipeline and the production from the well. These mechanisms of precipitation of solids and creation of solid hydrates are well known in the art and have been the subject of study. The field of subsea production technology that deals with maintaining desired production flow is generally referred to as flow assurance.
Some efforts have been directed to determining whether the internal smoothness of the flow line or pipeline may be improved to prevent adherence of wax to pipeline walls. Similarly, coatings, either internally applied or flow applied, have been studied to determine if they can prevent solids from adhering to the pipeline walls. See, U.S. Pat. Nos. 5,254,366 and 5,020,561, which are herein incorporated by reference in their entirety. To date, there have been no successful field implementations of these techniques.
Other flow assurance means have been directed to modifying the pipeline environment itself. Insulated pipe such as U.S. Pat. No. 6,079,452 or pipe-in-pipe systems, such as U.S. Pat. No. 6,145,547 have become common. However, these systems only attempt to ameliorate the effects of subsea cold and operating pressure. Over large distances, even insulated pipe may not be effective in preventing deposition and pipeline clogging. A variation on the theme of attempting to control the pipeline environment is the use of electrically heated pipe or electrically heated pipe-in-pipe. See, U.S. Pat. Nos. 6,278,095 and 6,292,627. These systems can be effective but require significantly more expensive pipeline and heat support systems. For extremely long transport distances, the costs associated with these types of systems may be prohibitive.
Another means of flow assurance is the injection of chemicals that prevent blockage of the production stream. Common among these are thermodynamic inhibitors such as methanol and glycol. In this type of system, inhibitor is pumped through umbilical flow lines from the offshore structure to which the production stream is flowing to a point near the subsea production wellhead and injected into the production stream early in its transport. These types of systems require the laying and controlling of long length umbilical systems, as well as pumping means for pumping the inhibitor out to the injection point(s). If the inhibitor is separated from the production flow at the host, it must either be disposed of or recycled for continued flow assurance use. The equipment to support separation and recycling or disposal takes up offshore-structure deck space that might have otherwise been used for other production related activities. As such, chemical flow assurance, while effective, remains an expensive way to deal with the problem.
Another mechanical method of dealing with some flow assurance problems is the use of pipeline cleaning devices commonly known as “pigs.” There are numerous pig configurations that have been used all having the same basic idea, in that the pig diameter closely matches the inner diameter of the flow line or pipeline. A pig is introduced into the flow stream and scrapes wax deposits and scale from the inner wall of the pipeline. A pig handler is designed to launch a pig through a flow line, receive the pig at the end of the run and to re-launch the pig as required to maintain a clean flow line. There have been a number of pig handling systems used in various industries over the years as disclosed in U.S. Pat. Nos. 2,801,824; 4,079,782, 4,124,065; 4,283,807; 4,350,202; 4,420,038 4,556,102; 4,566,533; 5,284,581; 5,286,376; 5,427,680; 5,676,848; 5,888,407; 6,070,417; 6,336,238; 6,409,843; 6,409,843; 6,412,135; and 6,569,255. In the context of offshore pipelines and flow lines, pig launcher/receiver systems may be subsea based, as illustrated in U.S. Pat. No. 6,336,238 or they may be supported on an offshore structure, as illustrated in U.S. Pat. No. 5,842,816.
The use of host-based pigs and pig systems have been effective to some degree in deepwater systems. However, they also have some drawbacks. When being deployed in long subsea runs, the material scraped off the inside of the pipeline wall typically tends to form an agglomerated slug, requiring increasing pressure to push the pig through the flow line, further decreasing production.
A recent technique being explored is the idea of cold flow assurance. This technique utilizes the cold subsea environment to precipitate solids intentionally from the production stream using a dedicated heat exchanger or chilling loop. The production stream exits the wellhead and enters the chilling loop. The geometry and length of the chilling loop is a function of the deep sea water temperature, the production temperature, pressure and composition, and the temperatures and pressures at which the solids form. Following precipitation, the production stream enters into the flow line or pipeline. Recognizing that the solids will build up in the chilling loop, the chilling loop is equipped with its own pigging system. The pig is periodically released to clean out the chilling loop. Examples of this type of system are shown in U.S. Pat. Nos. 6,656,366 and 6,070,417.